1. Field of the Invention
The present invention relates to control systems and methods for fluid extraction from oil and gas wells. More particularly, the present invention relates to methodologies for controlling a downhole pump in an oil or gas well to optimize the fluid removal process and/or gas, oil, or water production. In another aspect, the present invention relates to systems and devices for optimal control of a flow control device. In yet another aspect, the present invention relates to systems and methods for monitoring and recording physical changes in a fluid body.
2. Description of the Related Art
Hydrocarbons (e.g., oil and gas) are recovered by drilling a wellbore in a subterranean formation having one or more hydrocarbon reservoirs. Under formation pressure or by artificial lift, the hydrocarbons flow up the wellbore and are recovered at the surface, a process commonly referred to as hydrocarbon production. In many instances, downhole devices such as pumps are used to assist in hydrocarbon production. For example, pumps are often used to control the levels of fluids in the wellbore (e.g., water, gas, oil), to provide a pressure boost to flow the wellbore fluids to the surface or other location, or to otherwise adjust the wellbore environment to maintain efficient production. Wellbore pumps are used in a number of applications, including: conventional oil production, heavy oil production, gas-dewatering, and coal-bed methane production.
Coal-bed methane production is illustrative of some aspects of wellbore or downhole pumps and associated control devices. Coal bed methane is methane that is found in coal seams. Methane is a significant by-product of coalification, the process by which organic matter becomes coal. Often the coal seams are at or near underground water or aquifers, and coal bed methane production is reliant on manipulation of underground water tables and levels. The underground water often saturates the coal seam where methane is found, and the underground water is often saturated with methane. The methane may be found in aquifers in and around coal seams, whether as a free gas or in the water, adsorbed to the coal or embedded in the coal itself. Methane is a primary constituent of natural gas. Recovery of coal bed methane can be an economic method for production of natural gas. Such recovery is now pursued in geologic basins around the world. However, every coal seam that produces coal bed methane has a unique set of reservoir characteristics that determine its economic and technical viability.
Methods of coal bed methane recovery vary from basin to basin and operator to operator. However, a typical recovery strategy is when a well is drilled into the coal seam, usually a few hundred to several thousand feet below the surface. Thereafter, a casing is set and cemented in place and a water pump and gas separation device are installed. The water pump is operated to remove water from the coal seam at a rate appropriate to reduce the hydrostatic pressure exerted on the formation fluids. When the hydrostatic pressure is sufficiently low, the methane desorps from the coal. However, because the rate of desorption varies roughly inversely with the exerted hydrostatic pressure, dropping the hydrostatic pressure too low may result in a rate of methane production that can overwhelm the methane recovery equipment. Thus, control over the water head or height of a water column in the well is a significant factor in the production of methane.
In conventional coal-seam gas wells, submersible pumps with variable speed controllers are used as liquid removal systems. Typically, these pumps are controlled in response to a determination of the water level in the wellbore. A conventional arrangement includes a liquid level sensor that uses a pressure responsive switch. For instance, the system can have an electrical control circuit including a switch which operates to turn on the water pump motor when the water level in the well reaches a certain high level (as measured by the pressure responsive switch) and to turn off the pump motor the water level reaches a certain low level in the well. These sensors are exemplary of mechanical sensors—i.e., sensors that mechanically co-act with the sensed fluid in order to measure a condition in the wellbore (e.g., the presence or absence of surrounding water). For example, an element of a pressure switch moves or compresses in response to hydrostatic pressure or a float member of a float switch moves in response to buoyancy force. The mechanical and electrical elements of such mechanical devices can be prone to sticking, wear and corrosion. Thus, a long-standing and persistent drawback of such sensors is that their operating life can be much shorter than the life of a production well. The cost accompanying the cessation of gas or oil production to repair or replace an inoperative sensor can be significant.
Pump control devices utilizing mechanical sensors encounter similar modes of failure when used in conventional oil pump control, heavy oil pump control, and gas-dewatering pump control. In these applications as well, production objectives such as maintaining a fluid level between specific levels to optimize the production, avoiding pumping the well off, optimizing energy consumption, and reducing wear and tear on the pump are in large measure contingent upon reliable devices and methodologies for controlling downhole pumps and other such devices. More generally, the need to reliably control pump operation arises in other applications such as refineries, water treatment plants, chemical production facilities, underground gas or liquid, storage caverns, and other instances wherein the level/quantity/flow rate/velocity of fluid is controlled or wherein the mixture or ratio of fluids is controlled.
The present invention addresses these and other drawbacks of the prior art.